A typical fixed-cutter, or “drag,” rotary drill bit for drilling subterranean formations includes a bit body having a face region thereon carrying cutting elements for cutting into an earth formation. The bit body may be secured to a hardened steel shank having a threaded pin connection for attaching the drill bit to a drill string that includes tubular pipe segments coupled end to end between the drill bit and other drilling equipment. Equipment such as a rotary table or top drive may be used for rotating the tubular pipe and drill bit. Alternatively, the shank may be coupled directly to the drive shaft of a down-hole motor to rotate the drill bit.
Typically, the bit body of a drill bit is formed from steel or a combination of a steel blank embedded in a matrix material that includes hard particulate material, such as tungsten carbide, infiltrated with a binder material, such as a copper alloy. A steel shank may be secured to the bit body after the bit body has been formed. Structural features may be provided at selected locations on and in the bit body to facilitate the drilling process. Such structural features may include, for example, radially and longitudinally extending blades, cutting element pockets, ridges, lands, and drilling fluid courses and passages. The cutting elements generally are secured within pockets that are formed into blades located on the face region of the bit body, either by machining if the bit body is steel or other machinable materials, or during the formation of the bit body of a matrix-type bit using displacements sized and configured to provide the pockets.
FIG. 1 illustrates a conventional fixed-cutter rotary drill bit 100 generally according to the description above. The rotary drill bit 100 includes a bit body 102 that is secured to a steel shank 112. The bit body 102 includes a crown 108 and a steel blank 110 that is embedded in the crown 108. The crown 108 includes a particle-matrix composite material such as, for example, particles of tungsten carbide embedded in a copper alloy matrix material. The bit body 102 is secured to the steel shank 112 by way of a threaded connection 114 and a weld 116 that extends around the drill bit 100 on an exterior surface thereof along an interface between the bit body 102 and the steel shank 112. The steel shank 112 includes an API threaded pin 118 for attaching the drill bit 100 to a drill string (not shown).
The bit body 102 includes wings or blades 120, which are separated by junk slots 122. Internal fluid passageways 105 extend between the face 124 of the bit body 102 and internal fluid plenum 126, which extends through the steel shank 112 and partially through the bit body 102. Nozzle inserts 136 may be provided at face 124 of the bit body 102 within the internal fluid passageways 105.
A plurality of polycrystalline diamond compact (PDC) cutters 128 is provided on the face 124 of the bit body 102. The PDC cutters 128 may be provided along the blades 120 within pockets 130 formed in the face 124 of the bit body 102, and may be supported from behind by buttresses 132, which may be integrally formed with the crown 108 of the bit body 102.
During drilling operations, the drill bit 100 is positioned at the bottom of a well borehole and rotated while drilling fluid, or “mud,” is pumped to the face 124 of the bit body 102 through the internal fluid plenum 126 and the internal fluid passageways 105. The drilling fluid cools and cleans the PDC cutters 128 on face 124 of the bit body 102 and flushes debris removed by the drill bit 100 from the subterranean formation being drilled from the face 124 of the bit body 102 and up the wellbore annulus. Throughout the drilling process, the pumping of the drilling fluid may be periodically stopped, such as when additional drill pipe is added to the drill string. Drilling fluid in the wellbore annulus outside the drill string includes formation cuttings resulting from the drilling process and, thus, may be relatively denser than the drilling fluid within the drill string. As a result, when the pumping of the drilling fluid halts, drilling fluid, cuttings, and debris in the wellbore annulus may flow in reverse back into the internal fluid passageways 105 and the internal fluid plenum 126. This phenomenon is often referred to in the art as the “U-tube effect.” Large cuttings and debris that enter the internal fluid passageways 105 due to the U-tube effect may accumulate and become trapped in the internal fluid passageways 105 or the internal fluid plenum 126. As a result, when the pumping of the drilling fluid is restarted, some or all of the internal fluid passageways 105, as well as the internal fluid plenum 126, may become blocked or clogged. Consequently, time and money must be expended to unblock the internal fluid passageways 105 and the internal fluid plenum 126 so that the drilling fluid may adequately flow through the internal fluid passageways 105 and the internal fluid plenum 126 for efficient drilling.